This invention defines a particular novel arrangement, which can reduce drilling costs in deep ocean and greatly improve the safe handling of the hydrocarbon gas or liquids that may escape the subsurface formation below seabed and then pumped from the subsurface formation with the drilling fluid to the drilling installation that floats on the ocean surface. By performing drilling operations with this novel arrangement as claimed, there is provided a complete new way of controlling the pressure in the bottom of the well and at the same time safely and efficiently handling hydrocarbons in the drilling riser system. The arrangement comprises the use of prior known art but arranged so that totally new drilling methods is achieved. By arranging the various systems coupled to the drilling riser in this particular way, totally new and never before used methods can be performed safely in deepwater. The invention relates to a deep water drilling system, and more specifically to an arrangement for use in drilling of oil/gas wells, especially for deep water wells, preferably deeper than 500 m water-depth.
Experience from deepwater drilling operations has shown that the subsurface formations to be drilled usually have a fracture strength close to that of the pressure caused by a column of seawater.
As the hole deepens the difference between the formation pore pressure and the formation fracture pressure remains low. The low margin dictates that frequent and multiple casing strings have to be set in order to isolate the upper rock sections that have lower strength from the hydraulic pressure exerted by the drilling fluid that is used to control the larger formation pressures deeper in the well. In addition to the static hydraulic pressure acting on the formation from a standing column of fluid in the well bore there are also the dynamic pressures created when circulating fluid through the drill bit. These dynamic pressures acting on the bottom of the hole are created when drill fluid is pumped through the drill bit and up the annulus between the drill string and formation. The magnitude of these forces depends on several factors such as the rheology of the fluid, the velocity of the fluid being pumped up the annulus, drilling speed and the characteristics of the well bore/hole. Particularly for smaller diameter hole sizes these additional dynamic forces become significant. Presently these forces are controlled by drilling relatively large holes thereby keeping the annular velocity of the drilling fluid low and by adjusting the rheology of the drilling fluid. The formula for calculating these dynamic pressures is stated in the following detailed description. This new pressure seen by the formation in the bottom of the hole caused by the drilling process is often referred to as Equivalent Circulating Density (ECD).
In all present drilling operations to date in offshore deepwater wells, the bottom of the well will observe the combined hydrostatic pressure exerted by the column of fluid from the drilling vessel to the bottom of the well, plus the additional pressures due to circulation. A drilling riser that connects the seabed wellhead with the drilling vessel contains this drilling fluid. The bottom-hole pressure to overcome the formation pressure is regulated by increasing or decreasing the density of the drilling fluids in conventional drilling until the casing has to be set in order to avoid fracturing the formation.
In order to safely conduct a drilling operation there has to be a minimum of two barriers in the well. The primary barrier will be the drilling fluid in the borehole with sufficient density to control the formation pressure, also necessary in the event that the drilling riser is disconnected from the wellhead. This difference in pressure caused by the difference in density between seawater and the drilling fluid can be substantial in deep water. The second barrier will be the blowout preventer (BOP) in case the primary barrier is lost.
As the drilling fluid must have a specific gravity such that the fluid remaining in the well is still heavy enough to control the formation when the drilling marine riser is disconnected, this creates a problem when drilling in deep waters. This is due to the fact that the marine riser will be full of heavy mud when connected to the sub sea blowout preventer, causing a higher bottom-hole pressure than required for formation control. This results in the need to set frequent casings in the upper part of the hole since the formation cannot support the higher mudweight from the surface.
In order to be able to drill wells with a higher density drilling fluid than necessary, multiple casings will be installed in the borehole for isolation of weak formation zones.
The consequences of multiple casing strings will be that each new casing reduces the borehole diameter. Hence the top section must be large in order to drill the well to its planned depth. This also means that slimhole or slender wells are difficult to construct with present methods in deeper waters.
Several prior art describe and suggest methods to solve and simplify this problem. First the system of “dual gradient drilling” will be explained.
Reference is made to U.S. Pat. Nos. 4,291,722, 4,813,495 and 6,263,981 as examples of prior art publications describing a system with a different density liquid in the riser (or seawater with no riser) than the drilling mud, which is most often used as a drilling fluid, and which is returning from the well bore. U.S. Pat. No. 4,291,722 specifies the lighter fluid to be seawater and is excluding the use of air. U.S. Pat. No. 4,291,722 describes that the liquid level of the lighter density riser fluid is close to or near the seawater level and with a liquid/air interface close to the sea-level and above an annular BOP that is placed below the sea level. The system of U.S. Pat. No. 4,291,722 indicates a low-pressure riser with conventional kill and choke lines running in parallel with the drilling riser form a subsea BOP up to the surface vessel. Hence U.S. Pat. No. 4,291,722 is a dual gradient system.
In dual gradient systems, liquids with different densities will be present in the borehole and riser, thus being able to drill longer section without having to set a new casing. However in all systems explained to date there is a conventional low-pressure drilling riser with choke and kill lines running back to the surface vessel or platform from the subsea BOP. This gives rise to several grave problems if having to handle hydrocarbons and in kick and well control handling.
Reference is also made to U.S. Pat. Nos. 4,091,881 and 4,063,602. Both these publications describe a “single” gradient and a liquid level below the surface of water. U.S. Pat. No. 4,063,602 describes a fluid return pump installed in the lower part of a drilling riser system. The return fluid from the well may be pumped back to the surface through a conduit line or discarded to the ocean, through an opening valve. The valve or the returns pump controls the level in the riser. This invention also claims to detect the pressure inside the riser with the means of an electrical signal.
U.S. Pat. No. 4,063,602 does not have a pressure containment envelope or surface BOP in order to handle severe kick situations or handle continuous gas production from subsurface formations as during under-balanced drilling conditions.
WO99/18327 shows a system with a riser-mounted pump that resembles that of U.S. Pat. No. 4,063,602 mounted to a conventional riser with outside kill and choke lines. The riser is open to the surface and contains a low pressure slip joint between the point where the riser section is tensioned to the drilling vessel and the drilling vessel itself. The pump(s) are mounted on the outside of the drilling riser and the drilling return mud will be pumped through the pump and routed via the kill and choke lines on the outside of the drilling riser. Some instrumentation device on the riser section will control the level in the riser. The level will be significantly below the drilling vessel and significantly above the seabed.
This prior art publication intends to compensate for the “riser-margin” effect in deep water. It does not make any mention of the dynamic effects of the drilling operation itself such as the ECD, surge and swab effects.
The dropping of the level in the riser to a predetermined level is described in U.S. Pat. No. 4,063,602. This prior art can not be used for under-balanced purposes where the drilling riser is used for gas separation, since the prior art does not have a surface pressure containment system that can be used for gas pressure containment. Nor does it incorporate the particular benefit achieved by not having the need for the kill and choke lines and the high pressure riser bypass in well control situations.
Attention is then raised to U.S. Pat. Nos. 5,848,656 and 5,727,640. These show the benefit of using both a surface and a subsea BOP so as to eliminate the use of conventional outside kill and choke lines in the drilling riser at great water depth. U.S. Pat. No. 5,727,640 relates to an arrangement to be used when drilling oil/gas wells, especially deep water wells, and the publication gives instructions for how to utilize the riser pipe as part of a high pressure system together with the drilling pipe, namely in that the arrangement comprises a surface blowout preventer (SURBOP) which is connected to a high pressure riser pipe (SR) which in turn is connected to a well blowout preventer (SUBBOP), and a circulation/kill line (TL) communicating between said blowout preventers (SURBOP, SUBBOP), all of which being arranged as a high pressure system for deep water slim hole drilling.
U.S. Pat. No. 5,848,656 relates to a device for controlling underwater pressure, which device is adapted for use in drilling installation comprising subsea blowout preventer and surface blowout preventer, between which a riser is arranged for communication, and for the purpose of defining a device in which the use of choke line and kill line can be avoided.
These two above-mentioned examples of prior art, however, does not incorporate a method to adjust and compensate for the ECD effect. In order to achieve ECD compensation it is necessary to introduce the low riser return outlet and drop down the liquid level in the riser. It is particularly important since a high pressure riser will by definition be of smaller (typically 14″-9″) inside diameter than a conventional drilling riser (typically 21″-16″) and hence the ECD effect in a high pressure riser can be considerably higher than conventional in a deepwater well.
Attention is then raised to U.S. Pat. Nos. 4,046,191, 4,210,208 and 4,220,207. The bypass or pressure equalizing line, bypassing in the drilling BOP so as to equalize the pressure below a closed in subsea BOP into the drilling riser, is well known and described in the literature. Some equalizing loops contain hydraulic choke valves while other systems define closed/open valves.
Further attention is raised to U.S. Pat. No. 6,415,877. This publication refers to an apparatus using a pump and the suction from a pump to regulate and reduce the bottom hole pressure in the well being drilled. In U.S. Pat. No. 6,415,877 this requires and specifies a drilling operation performed through a closed pressure containment envelope around the drill string at seabed.
Normally it is not possible to control the pressure from the surface in a conventional drilling operation, due to the fact that the well returns will flow into an open flow line at atmospheric pressure. In order to obtain wellhead pressure control, the well return has to be routed through a closed flow line by way of a closed blow out preventer to a choke manifold. The advantage of controlling bottom hole pressure by means of wellhead pressure control is that a pressure change at the surface results in an almost instantaneous pressure response at the bottom of the hole when a single-phase drilling fluid is used. In general, the surface pressure should be kept as low as possible to obtain safer working environment for the personnel working on the rig. So, it is preferable to control the well by changing pressures in the well bore to the largest extent. Conventionally, this can be performed by means of hydrostatic pressure control and friction pressure control in the annulus.
Hydrostatic pressure control is the prime means of bottom hole pressure control in conventional drilling. The mud weight will be adjusted so that the well is in an overbalanced condition in the well when no drilling fluid circulation takes place. If needed, the mud weight/density can be changed depending on formation pressures. However, this is a time consuming process and requires adding chemicals and weighting materials to the drilling mud.
The other method for bottom hole pressure control is friction pressure control. Higher circulating rates generates higher friction pressure and consequently higher pressures in the bore hole. A change in pump rate will result in a rapid change in the bottom hole pressure (BHP). The disadvantage of using frictional pressure control is that control is lost when drilling fluid circulation is stopped. Frictional pressure loss is also limited by the maximum pump rate, the pressure rating of the pump and by the maximum flow through the down hole assembly.
All and each of the above references are hereby incorporated by reference.
The above prior art has many disadvantages. The object of the present invention is to avoid some or all of the disadvantages of the prior art.